Formation waters are often produced concurrently with oil and/or gas. Higher amounts of produced waters occur during the middle or later stage of the primary production after water breakthrough. A further increase in the amounts of such waters also occurs during the secondary treatment, in which large amounts of waters are injected from the surface into the reservoir formation to sustain oil and/or gas production. In some cases, the amounts of produced waters could reach 90% or more of the total fluids produced.
Chloride is the dominant anion in most produced waters, with the exception of a few cases where sulfate and bicarbonate exceed chloride by weight. Chloride-rich produced waters that are high in calcium (in larger portions than in seawater) are generally high in alkaline cations such as strontium, barium, and in some cases radium. The availability of radium in produced waters suggests that the decay chain of radium, referred to as Naturally Occurring Radioactive Materials (NORM), are common and thus such waters can become radioactive.
Factors such as: (1) changes in pressure or temperature or pH or combinations of these parameters; (2) variations in flow rates, impurities, additives, fluid expansion, and gas evaporation; and (3) mixing of incompatible waters cause scale formation (mainly strontium and barium in the form of sulfate). However, the mixing of incompatible waters is the primary reason for scale formation. The formation of scale salts can lead to production problems in primary oil wells, secondary oil wells, injection wells, disposal wells, pipelines, and process equipment. In addition, external radiation (near any processing equipment) and internal radioactive hazards (during maintenance or workover) could exist due to NORM buildup during processing, referred to as Technologically Enhanced Naturally Occurring Radioactive Materials (TENORM).
In offshore oil and gas reservoirs (e.g., Gulf of Mexico, North Sea, etc.), pressure maintenance with water injection is required over the reservoir life to maintain oil and/or gas production. The salinity of seawater is to a large extent compatible with the salinity of produced waters in most reservoirs. Table 1 presents the concentrations of inorganics in seawater and samples of produced waters (Hardy, J. A. and Simm, I., xe2x80x9cLow Sulfate Seawater Mitigates Barite Scalexe2x80x9d Oil and Gas J. (1996) Dec. 9: 64-67). Barium and strontium in produced waters are typically in the form of chloride. However, direct injection of seawater, with about 2,700 ppm of sulfate ion, would react with barium and strontium in the reservoirs, to form sulfate scales. This would lead to flow problems and subsequent plugging in producing wells as well as possible formation of a significant radioactive scale. In spite of a large number of proprietary chemicals in blends available as scale inhibitors and dissolvers, scale prevention with such chemicals has proved difficult, very expensive, and of limited value for solving the scale problem or protecting the reservoir formation matrix. Injection of potable water (although it""s an expensive option in offshore fields) could damage the formation by causing clays in the reservoir matrix to swell and block pores (incompatible salinity). Nearly-sulfate free seawater would be acceptable for injection into offshore and some onshore reservoirs. This would also prevent the reservoir from souring (due to sulfate conversion to hydrogen sulfide via thermophilic sulfate reducing bacteria). However, the nearly-sulfate free seawater substantially minimizes but not entirely eliminates scale formation (due to the very low aqueous solubilities of barium and strontium sulfate).
Another example of incompatible waters is the mixing of produced waters from different production zones. It is not uncommon that the chemistry of produced waters differs considerably from zone to zone within the same processing facilities. The mixing of incompatible waters causes almost immediate scale build-up, which leads to expensive problems (e.g., stuck downhole pumps, plugged perforations and tubing strings, choked flowlines, frozen valves, equipment damage, and downtime during maintenance).
A further example of mixing incompatible waters is that nearly all onshore oil-field produced waters are injected into subsurface formation through injection wells. In addition to the possible formation of scale and NORM hazards, two further problems are of major concern. The first problem is the seepage of the disposed produced waters to contaminate (mainly salinity and possibly radioactivity) sources of potable waters such as near by rivers, lakes, and shallow groundwater. The second problem is the incompatibility between the injected produced waters and the existed formation water in the disposal wells that could lead to destroy the injectivity by plugging the pores of the permeable zone in the disposal wells.
These two problems can be illustrated in the natural brine seepage into the Dolores River in Paradox Valley (Colorado), which increases the dissolved solids of the Colorado River annually by about 200 million kilograms. The Colorado River is a major source of water for both the United States and the Republic of Mexico. To solve this problem, about 3540 cubic meters per day of brine needs to be pumped from shallow brine wells (TDS: 250,000 ppm) located along the Dolores River into a very deep injection well (Mississippian Leadville Limestone). This volume of continuous pumping is needed to create a cone of depression in the brine field near the river that should fill with freshwater and stop brine seepage. Table 2 presents the concentrations of inorganic species from several brine wells and the injection well (Kharaka, Y. K., et al., xe2x80x9cDeep Well Injection from Paradox Valley, Colo.: Potential Major Precipitation Problems Remediated by Nanofiltrationxe2x80x9d, Water Resour. Res. (1997) 33: 1013-1020). The injection of such brine waters into the formation water of the injection well clearly will lead to the formation of a huge mass of calcium sulfate in conjunction with barium and strontium sulfate at downhole. This would plug the permeable zone of the injection well.
The pressure-driven nanofiltration (NF) membrane process is a potential technology for solving such sulfate scale problems. NF organic membranes are capable of efficiently rejecting divalent ions while retaining monovalent ions. FIG. 1 depicts the rejection of magnesium sulfate and sodium chloride by NF (Davis, R., et al., xe2x80x9cMembranes Solve North Sea Waterflood Sulfate Problemsxe2x80x9d Oil and Gas J. (1996) Nov. 25: 59-64). The rejection of sulfate is constantly very high (about 98%) regardless of the operating pressures, while the rejection of chloride is relatively low and increases with the increase of the operating pressures. However, several problems are associated with the use of NF.
First, extensive pretreatment is essential for reliable NF system, particularly in the case of treating seawater. Chemical coagulation (polyelectrolyte) and pre-filtration are needed to coagulate suspended particles to sufficient sizes so that they can be removed via filtration. Bacteria remediation (adding sodium hypochlorite or free chlorine to seawater) is also needed to prevent bacteria growth (plugs the pores of the organic membrane) and subsequent biofilm formation resulting in biological membrane fouling. This would, in turn, require: (1) the addition of sodium metabisulfate to remove the added chlorine, and thus to prevent it from oxidizing the membrane; and (2) placement of a de-oxygenation or a de-aerator system (to reduce oxygen content).
Second, NF membranes recover at best 75% of the feed stream. The remaining 25% (concentrate stream) represents one-fourth of the feed stream and thus contains roughly four-times the initial concentrations of the feed species. For instance, the high rejection of 2,700 ppm of sulfate (about 98%) from seawater roughly translates to 11,000 ppm in the concentrate stream. About one-third of calcium is simultaneously rejected with sulfate. The combined increase in the rejected amounts of sulfate and calcium leads to the precipitation of calcium sulfate (aqueous solubility is about 2,400 ppm at 25xc2x0 C.) on the concentrate side of the membrane, and causes membrane fouling. As such, anti-scale chemicals are constantly needed to retard the formation of calcium sulfate and protect the membrane. Other scale foulants such as calcium carbonate, iron sulfide, or combinations are also of concern.
Third, the remaining 25% of the concentrate stream in the NF process represents a large secondary waste stream. The disposal of such a highly concentrated waste stream with scale/radioactive foulants is an additional critical problem. This demonstrates that the high removal (more than is necessary) of sulfate by NF and without operational controls is not always advantageous.
Fourth, membrane throughput (permeate flux) depends on the concentration of inorganics in the feed solution as well as the temperature of the feed solution. As shown in Tables 1 and 2, the osmotic pressure (xcfx80) of seawater is about 410 psia while osmotic pressures of the reported produced waters are extremely high due to high levels of sodium chloride. Although a portion of sodium chloride passes through the NF membrane under moderate throughput operation (FIG. 1), higher operating pressures are required to achieve acceptable permeate throughput. This would increase the rejection of sodium chloride, which, in turn, would increase the osmotic pressure of the solution across the membrane. In addition, low feed temperatures increase the viscosity of water, and thus higher operating pressures (3 to 4.8% increase per 1xc2x0 C.) are required to diffuse water through the membrane. For instance, the temperature of the North Sea is less than 15xc2x0 C., which requires an operating pressure of 600 psia (about the structural pressure limits of most NF modules). As such, operating the NF process at relatively low permeate throughput, and/or increasing feed water temperature are respectively the two costly options in treating aqueous streams containing high levels of chloride salts, or operating in a cold climate.
Therefore, what is needed is an effective method that would selectively remove scale/NORM salts from seawater, oil-field produced waters, brine waters, and the like. As such, this invention is directed first to provide a highly selective method for separating sulfate and polyvalent cations (calcium, strontium, barium, radium and it""s decay chain, and others) from such aqueous streams, and second to implement a cost-effective proactive method to prevent scale/NORM formation rather than allowing it to be formed, and then coping with the costs of dissolution and disposal of the formed scale/NORM.
In the case of injecting seawater into reservoirs to maintain pressure, downhole scale formation occurs after the injection of the treated seawater breaks through at a producing well where barium-strontium containing produced waters are co-interacted with remaining sulfate in the treated seawater. A better solution to this problem is to: (1) treat at least a portion of oil-field produced water by selectively removing barium, strontium, and radium (if it exists); (2) treat seawater by selectively separating sulfate; (3) blend the treated oil-field produced water with the treated seawater to produce scale-free saline water; and (4) inject the scale-free saline water into reservoirs formation as a pressure support to maintain oil and gas production. The production rate of oil-field produced water, the concentration profile of alkaline cations in such water, and the needed amount of scale-free saline water for pressure support determine the extent and the proportions of oil-field produced water and seawater that need to be treated.
Several vital concerns would be resolved. First, blend scale-free saline water is more compatible with the reservoir formation than sulfate-free seawater. Second, scale formation can be monitored before injection into reservoirs, an effective and preventive measure to protect the reservoir formation (minimizes, if not eliminates, the costly scale inhibitors treatment). Third, provide a readily available source of scale-free saline water for use in routine well-service operations. Fourth, protect the sea aquatic life from direct discharging of produced waters (e.g., radioactivity of NORM; salinity reaches in some cases 200,000 ppm; temperatures reach in some cases 100xc2x0 C.; and depleted of dissolved oxygen). Fifth, potential cost (capital and operating) savings.
This approach can be equally applied to other cases of mixing incompatible waters such as the processing of oil-field produced waters from different production zones (different chemistry) in the same oil and gas production facilities, or the disposing of formation waters in deep injection wells.
In one aspect, the present invention provides a method of producing petroleum, gas, or other products from a subterranean formation using seawater. The inventive method comprises the steps of: (a) removing natural sulfate from the seawater; and (b) injecting the resulting treated seawater product into the subterranean formation. Natural sulfate is removed from the seawater in step (a) by (i) concentrating calcium sulfate in seawater to near saturation by membrane distillation; (ii) adding an organic solvent to the seawater in an amount effective to form a precipitate comprising the sulfate; (iii) removing at least most of the organic solvent from the aqueous stream by vacuum membrane distillation; and (iv) removing the precipitate from seawater to produce the treated seawater product. The organic solvent employed in the inventive method is preferably isopropylamine, ethylamine, or a combination thereof
In another aspect, the present invention provides a method of producing petroleum, gas, or other products from a subterranean formation using formation-produced water. The inventive method comprises the steps of: (a) removing natural, inorganic material from the formation-produced water; and (b) injecting the resulting treated water product into the subterranean formation. In step (a), the natural, inorganic material is removed from the formation-produced water by (i) adding organic solvent to the formation-produced water in an amount effective to form a precipitate comprising the inorganic material; (ii) removing at least most of the organic solvent from the aqueous stream by vacuum membrane distillation; and (iii) removing the precipitate from the formation-produced water to yield the treated water product. The organic solvent employed in the inventive method is preferably isopropylamine, ethylamine, or a combination thereof. The natural inorganic material contained in the formation-produced water will typically comprise at least one of sulfate, calcium, barium, strontium, radium, Naturally Occurring Radioactive Material, silica and silicate.
In another aspect, the present invention provides a method of producing petroleum, gas, or other products from a subterranean formation using seawater and/or formation-produced water. The inventive method comprises the steps of: (a) removing natural sulfate from the seawater (or other formation-brine water); (b) removing natural inorganic material from the formation-produced water; (c) blending the treated water in steps (a) and (b) to produce scale-free saline water; and (d) injecting the resulting scale-free saline water product from step (c) into the subterranean formation. In step (a), the natural sulfate is removed from the seawater by (i) concentrating calcium sulfate in seawater to near saturation by membrane distillation; (ii) adding an organic solvent to the seawater in an amount effective to form a precipitate comprising the sulfate; (iii) removing at least most of the organic solvent from the aqueous stream by vacuum membrane distillation; and (iv) removing the precipitate from seawater to produce the treated seawater product. In step (b), the natural inorganic material are removed from the formation-produced water by (i) adding an organic solvent to the formation-produced water in an amount effective to form a precipitate comprising the natural sulfate and inorganic material; (ii) removing at least most of the organic solvent from the aqueous stream by vacuum membrane distillation; and (iii) removing the precipitate from the treated water to yield scale-free saline water product. The organic solvent employed in the inventive method is preferably isopropylamine, ethylamine, or a combination thereof. The natural inorganic material contained in the seawater and formation-produced water will typically comprise at least one of sulfate, calcium, barium, strontium, radium, Naturally Occurring Radioactive Material, silica and silicate.
In yet another aspect, the present invention provides a method of treating an aqueous stream having inorganic material dissolved therein, the inventive method comprising the steps of: (a) distilling the aqueous stream by membrane distillation to produce an aqueous permeate product and an intermediate concentrate comprising at least most of the inorganic material; (b) adding an organic solvent to the intermediate concentrate in an amount effective to form a precipitate comprising at least a portion of the inorganic material; (c) removing at least most of the organic solvent from the intermediate concentrate by vacuum membrane distillation; and (d) removing at least most of the precipitate from the intermediate concentrate to produce a concentrate product and an at least partially purified aqueous product. The organic solvent employed in the inventive method is preferably isopropylamine, ethylamine, or a combination thereof. The inorganic material removed by the inventive method will typically comprise at least one of aluminum, titanium, vanadium, chromium, manganese, iron, cobalt, nickel, cadmium, zinc, zirconium, cerium, praseodymium, neodymium, promethium, samarium, europium, gadolinium, terbium, dysprosium, holmium, erbium, thulium, ytterbium, lutetium, thorium, uranium, silicate and silica.